1. Field of the Invention
This invention relates to desulfurization of hydrocarbon streams, and in particular to a system and process for integrated hydrotreating and oxidative desulfurization of hydrocarbon streams to produce reduced sulfur-content hydrocarbon fuels.
2. Description of Related Art
The discharge into the atmosphere of sulfur compounds during processing and end-use of the petroleum products derived from sulfur-containing sour crude oil pose health and environmental problems. The stringent reduced-sulfur specifications applicable to transportation and other fuel products have impacted the refining industry, and it is necessary for refiners to make capital investments to greatly reduce the sulfur content in gas oils to 10 parts per million by weight (ppmw), or less. In industrialized nations such as the United States, Japan and the countries of the European Union, refineries for transportation fuel have already been required to produce environmentally clean transportation fuels. For instance, in 2007 the United States Environmental Protection Agency required the sulfur content of highway diesel fuel to be reduced 97%, from 500 ppmw (low sulfur diesel) to 15 ppmw (ultra-low sulfur diesel). The European Union has enacted even more stringent standards, requiring diesel and gasoline fuels sold in 2009 to contain less than 10 ppmw of sulfur. Other countries are following in the direction of the United States and the European Union and are moving forward with regulations that will require refineries to produce transportation fuels with an ultra-low sulfur level.
To keep pace with recent trends toward production of ultra-low sulfur fuels, refiners must choose among the processes or crude oils that provide flexibility to ensure that future specifications are met with minimum additional capital investment, in many instances by utilizing existing equipment. Conventional technologies such as hydrocracking and two-stage hydrotreating offer solutions to refiners for the production of clean transportation fuels. These technologies are available and can be applied as new grassroots production facilities are constructed. However, many existing hydroprocessing facilities, such as those using relatively low pressure hydrotreaters, were constructed before these more stringent sulfur reduction requirements were enacted and represent a substantial prior investment. It is very difficult to upgrade existing hydrotreating reactors in these facilities because of the comparably more severe operational requirements (i.e., higher temperature and pressure conditions) to obtain clean fuel production. Available retrofitting options for refiners include elevation of the hydrogen partial pressure by increasing the recycle gas quality, utilization of more active catalyst compositions, installation of improved reactor components to enhance liquid-solid contact, the increase of reactor volume, and the increase of the feedstock quality.
There are many hydrotreating units installed worldwide producing transportation fuels containing 500-3000 ppmw sulfur. These units were designed for, and are being operated at, relatively milder conditions, i.e., low hydrogen partial pressures of 30 kilograms per square centimeter for straight run gas oils boiling in the range of 180 C.°-370° C.
However, with the increasing prevalence of more stringent environmental sulfur specifications in transportation fuels mentioned above, the maximum allowable sulfur levels are being reduced to no greater than 15 ppmw, and in some cases no greater than 10 ppmw. This ultra-low level of sulfur in the end product typically requires either construction of new high pressure hydrotreating units, or a substantial retrofitting of existing facilities, e.g., by integrating new reactors, incorporating gas purification systems, reengineering the internal configuration and components of reactors, and/or deployment of more active catalyst compositions. Each of these options represents a substantial capital investment
Hydrotreating/hydrocracking technology includes well-known processes and generally incorporates two main sections: reaction and separation. The configuration and types of separation sections typically depends upon the reactor effluent. Reactor effluents can be either sent to a hot separator (referred to in the industry as a “hot scheme”) or a cold separator (referred to in the industry as a “cold scheme”).
In a typical hydrotreating unit 10 schematically depicted in FIG. 1, feedstock 12 is introduced into a feedstock surge drum 14. A make-up hydrogen stream 16, after compression in a compressor 18, is mixed with feedstock from the surge drum 14, and the mixture is heated in a heat exchanger 20 using reactor effluents 30 as a source of thermal exchange. The partially heated feedstock-hydrogen mixture 22 is further heated to a suitable reaction temperature in a furnace 24, and the fully heated feedstock-hydrogen mixture 26 introduced to a catalytic reactor 28. In the catalytic reactor 28, the hydrocarbon feedstock is refined by removal of impurities such as sulfur and nitrogen using a hydrotreating catalyst as is conventionally known. Reactor effluents 30 are then cooled in the exchanger 20 and sent to a high pressure cold or hot separator 32.
Separator tops 34, including gaseous components H2S, NH3, and C1-C4, and some heavier components such as C5-C6, are separated in the high pressure separator 32 and sent for further cleaning in an amine unit 36. A hydrogen rich gas stream 38, essentially free of hydrogen sulfide, is passed to a recycling compressor 40 to be used as a recycle gas 42 in the catalytic reactor 28. The high pressure separator bottoms effluent stream 44, in a substantially liquid phase, is washed with process water introduced via a line 45 to prevent salt formation with any remaining H2S and NH3. Water is injected into the reactor effluents after the high pressure separator to prevent fouling by salt formation as a result of the byproducts according to the reaction NH3+H2S→NH4SH. Ammonium sulfide, soluble in water, can be removed from the system with the wastewater.
The mixture of bottoms effluent 44 and process water is typically cooled, for example using an air cooler 46, such as a fin fan cooler, and a water cooler 48, to a temperature of about 35° C. to about 60° C., preferably about 40° C. to about 50° C. The cooled bottoms from the high pressure separator are then introduced to a low pressure cold separator 50. Remaining gases, including H2S and NH3 and any light hydrocarbons, which can include C1-C4 hydrocarbons, are purged via line 54 from the low pressure cold separator 50 and sent for further processing, such as flare processing, fuel gas processing, or hydrogen recovery within the refinery complex containing the hydrotreating unit 10 (not shown). Water 52 is separated in the low pressure cold separator and the hydrocarbon fraction 56 is passed to the fractionator 58.
However, as mentioned above, most existing hydrotreating processes cannot remove all of the sulfur-containing compounds typically present in hydrocarbonaceous fuels. These sulfur-containing compounds include aliphatic molecules such as sulfides, disulfides and mercaptans as well as aromatic molecules such as thiophene, benzothiophene, dibenzothiophene (DBT) and alkyl derivatives such as 4,6-dimethyl-dibenzothiophene (DMDBT). The aromatic sulfur containing molecules have a higher boiling point than the aliphatic molecules, and are consequently more abundant in higher boiling fractions.
In addition, certain fractions of gas oils possess different properties. The following table illustrates the properties of light and heavy gas oils derived from Arabian Light crude oil:
TABLE 1Feedstock NameLightHeavyBlending RatioAPI Gravity37.5°30.5°Carbon85.99W %85.89W %Hydrogen13.07W %12.62W %Sulfur0.95W %1.65W %Nitrogen42ppmw225ppmwASTM D86 DistillationIBP/5 V %189/228°C.147/244°C.10/30 V %232/258°C.276/321°C.50/70 V %276/296°C.349/373°C.85/90V %319/330°C.392/398°C.95 V %347°C.Sulfur Speciation (ppmw)Sulfur Compounds Boiling45913923below 310° C.Dibenzothiophenes10412256C1-Dibenzothiophenes14412239C2-Dibenzothiophenes13252712C3-Dibenzothiophenes11045370
As set forth above in Table 1, the light and heavy gas oil fractions have ASTM D86 85/90 V % point of 319° C. and 392° C., respectively. Further, the light gas oil fraction contains less sulfur (0.95 W % as compared to 1.65 W %) and nitrogen (42 ppmw as compared to 225 ppmw) than the heavy gas oil fraction.
Advanced analytical techniques such as multi-dimensional gas chromatography with a sulfur chemiluminescence detector as described by Hua, et al. (Hua R., et al., “Determination of sulfur-containing compounds in diesel oils by comprehensive two-dimensional gas chromatography with a sulfur chemiluminescence detector,” Journal of Chromatography A, Volume 1019, Issues 1-2, Nov. 26, 2003, Pages 101-109) have shown that the middle distillate cut boiling in the range of 170-400° C. contains sulfur species including thiols, sulfides, disulfides, thiophenes, benzothiophenes, DBTs, and benzonaphthothiophenes, with and without alkyl substituents.
The sulfur speciation and content of light and heavy gas oils are conventionally analyzed by two methods. In a first method, sulfur species are categorized based on structural groups. The structural groups include one group having sulfur compounds boiling at less than 310° C., including DBTs and its alkylated isomers, and another group including 1, 2 and 3 methyl substituted DBTs, denoted as C1, C2 and C3, respectively. Based on this method, the heavy gas oil fraction contains more alkylated di-benzothiophene molecules than the light gas oils.
In a second method of analyzing sulfur speciation and content of light and heavy gas oils, and referring to FIG. 2, the cumulative sulfur concentrations are plotted against the boiling points of the sulfur compounds to observe concentration variations and trends. Note that the boiling points depicted are those of detected sulfur compounds, rather than the boiling point of the total hydrocarbons mixture. The boiling point of several of the refractory sulfur compounds consisting of DBTs, 4-methyl-dibenzo-thiophenes (MDBT) and 4,6-DMDBT are also shown in FIG. 2 for convenience. The cumulative sulfur speciation curves show that the heavy gas oil fraction contains a higher proportion of heavier sulfur compounds and a lower proportion of lighter sulfur compounds as compared to the light gas oil fraction. For example, it is found that 5370 ppmw of C3-DBT, and bulkier molecules such as benzo-naphtho-thiophenes, are present in the heavy gas oil fraction, compared to 1104 ppmw in the light gas oil fraction. In contrast, the light gas oil fraction contains a higher content of light sulfur compounds compared to heavy gas oil (4591 vs. 3923 ppmw). Light sulfur compounds are structurally less bulky than DBTs and boil at less than 310° C. Further, twice as much C1 and C2 alkyl substituted DBTs exist in the heavy gas oil fraction as compared to the light gas oil fraction.
Aliphatic sulfur compounds are more easily desulfurized, i.e., commonly referred to as “labile” using conventional hydrodesulfurization methods. However, certain highly branched aliphatic molecules can sterically hinder the sulfur atom removal and are moderately more difficult to desulfurize, i.e., commonly referred to as “refractory” using conventional hydrodesulfurization methods.
Among the sulfur-containing aromatic compounds, thiophenes and benzothiophenes are relatively easy to hydrodesulfurize. The addition of alkyl groups to the ring compounds slightly increases difficulty of hydrodesulfurization. DBTs resulting from addition of another ring to the benzothiophene family are even more difficult to desulfurize, and the difficulty varies greatly according to their alkyl substitution, with di-beta substitution being the most difficult to desulfurize, thus justifying their refractory appellation. These beta substitutes hinder the exposure of the heteroatom from the active site on the catalyst.
The economical removal of refractory sulfur compounds is therefore exceedingly difficult to achieve, and accordingly removal of sulfur compounds in hydrocarbonaceous fuels to ultra-low sulfur levels is very costly utilizing current hydrotreating techniques. When the sulfur specifications at previous levels permitted up to 500 ppmw, there was little need or incentive to desulfurize beyond the capabilities of conventional hydrodesulfurization, and hence the refractory sulfur compounds were not targeted. However, in order to meet the more stringent sulfur specifications, these refractory sulfur compounds must be substantially removed from hydrocarbonaceous fuels streams.
Relative hydrodesulfurization reactivities and activation of sulfur compounds are shown in the below table:
TABLE 2NameDBT4-MDBT4,6-DMDBTTemperature Reactivity k@250, s−157.710.41.0Reactivity k@300, s−17.32.51.0Activation Energy28.736.153.0Ea, Kcal/mol
Relative reactivities of sulfur compounds based on their first order reaction rates at 250° C. and 300° C., and 40.7 Kg/cm2 hydrogen partial pressure over Ni—Mo/Alumina catalyst are given (Steiner, P. et al., “Catalytic hydrodesulfurization of a light gas oil over a NiMo catalyst: kinetics of selected sulfur components,” Fuel Processing Technology, Vol. 79, Issue 1, Aug. 20, 2002, pages 1-12) in Table 2. DBT is 57 times more reactive than the refractory 4,6-DMDBT at 250° C. The relative reactivity decreases with increasing operating severity. With a 50° C. temperature increase, the relative reactivity of di-benzothiophene compared to 4,6-DMDBT decreases to 7.3 from 57.7.
Most known advances in the industry for minimizing these undesirable effects include development of more robust hydrotreating catalysts and advanced hydrodesulfurization reactor designs. Alternative processes have also been developed to meet the requirements of decreased sulfur levels in fuels and other petrochemical products.
The development of non-catalytic processes to carry out the final desulfurization of petroleum distillate feedstocks has been widely studied, and certain conventional approaches are based on oxidation of sulfur-containing compounds described in U.S. Pat. Nos. 5,910,440, 5,824,207, 5,753,102, 3,341,448 and 2,749,284.
Certain existing desulfurization processes incorporate both hydrodesulfurization and oxidative desulfurization. For instance, Cabrera et al. U.S. Pat. No. 6,171,478, Zinnen et al. US20050040078A1, and Kocal U.S. Pat. No. 6,277,271 describe integrated processes in which the hydrocarbon feedstock is first contacted with a hydrodesulfurization catalyst in a hydrodesulfurization reaction zone to reduce the sulfur content to the low sulfur level. The resulting hydrocarbon stream is then passed to a distinct oxidation zone containing an oxidizing agent where the residual sulfur is converted into oxidized sulfur compounds under mild conditions. After decomposing the residual oxidizing agent, the oxidized sulfur compounds are solvent extracted, resulting in an oxidized sulfur compound stream and a reduced sulfur hydrocarbon oil stream.
However, all of the aforementioned processes known in the art require construction and installation of a grass roots oxidation vessel to carry out the oxidative desulfurization.
Therefore, a need exists for an improved desulfurizing process and apparatus that minimizes the requirement of newly constructed and installed reaction vessels.
Therefore, it is an object of the present invention to modify existing hydrotreating units without the need to construct grass roots units and newly constructed and installed reaction vessels for oxidative desulfurization, thereby requiring very high capital investments.
It is another object of the present invention to provide such a modification that incorporates oxidative desulfurization step within a hydrodesulfurization unit thereby advantageously utilizing existing infrastructure in an efficient and effective manner.